If Shell Plc were to acquire BP Plc, it would be among the largest deals in European history, creating for the first time a European oil major that could challenge industry leaders Exxon Mobil Corp. and Chevron Corp. The circumstances for such a takeover might not be auspicious for BP — its shares have lost almost a third of their value in the last year and investors are unconvinced by the company’s turnaround plan — but the deal would be transformative for Shell. Since Bloomberg reported that Shell has been studying the merits of an acquisition — something both companies have so far declined to comment on — analysts have been gaming out both the upsides and downsides. Here are some of their conclusions: Oil Behemoth Combining the two London-based oil majors would create an energy giant with upstream oil and gas production of nearly 5 million barrels of oil equivalent a day, according to UBS Group. This would be an 85% increase from Shell’s current output of about 2.7 million barrels a day, making the combined company the largest investor-owned oil and gas producer. Exxon produced an average of 4.6 million barrels of oil equivalent a day in the first quarter, while Chevron pumped 3.4 million a day.  Adding BPX, the Denver-based US shale unit, to Shell’s portfolio would go some way to correct the company’s decision to sell its business in the Permian basin to ConocoPhillips in 2021, just before the industry experienced a major boom. Shell’s then-upstream director, Wael Sawan, is now chief executive officer.  LNG Dominance  Shell is already the world’s largest seller of liquefied natural gas, and acquiring BP would propel the business “to new heights,” said RBC. The combined companies’ LNG sales would jump to more than 90 million tonnes a year, representing more than 20%

Devon Energy Corp. and Ridgemont Equity Partners are divesting their interests in a natural gas pipeline serving the Permian Basin with a capacity of about 2.5 billion cubic feet a day. Put onstream November 2024, the Matterhorn Express Pipeline is fully contracted. The system consists of a 510-mile mainline and associated compression that carries gas from the Waha area to Wharton, Texas. It also has delivery capabilities for Katy, Texas, as well as laterals in the Midland Basin, according to operator WhiteWater Development LLC. The stake sales by Devon and Ridgemont will result in WhiteWater, MPLX LP and Enbridge Inc. owning 65 percent, 10 percent and 10 percent of the pipeline respectively, according to a joint statement. “WhiteWater’s equity interest in the Matterhorn Express Pipeline will be jointly backed by [infrastructure investors] FIC and I Squared, and WhiteWater will continue to operate the Matterhorn Express Pipeline”, said the statement posted on WhiteWater’s website. The parties expect to complete the transactions in the second quarter. MPLX separately said its side of the transaction consists of a 5 percent acquisition that would raise its stake to 10 percent for a purchase price of $151 million. Devon separately said it will receive about $375 million in proceeds. “Proceeds from the divestiture will be used to further strengthen the company’s investment-grade financial position”, it said in its quarterly report. “The monetization of Devon’s equity ownership will not change the terms or conditions of the company’s secured capacity on the pipeline”. In a separate transaction, Devon said in the report its partnership with BPX for the Blackhawk field in the Eagle Ford shale had been dissolved. That dissolution has resulted in Devon owning around 46,000 net acres with a stake of 95 percent and operatorship. For the first quarter (Q1), Devon reported $494 million in net profit.

The UK and Norway have formalised a green industrial partnership focused on the energy transition amid a week of setbacks for Labour’s clean power goals. UK energy secretary Ed Miliband travelled to Oslo to sign the deal alongside Norway’s trade and industry minister Cecilie Myrseth and energy minister Terje Aasland. The two governments first announced the partnership in December last year, stating their ambition to cooperate on carbon capture and storage (CCS) projects. Alongside CCS, the partnership will also focus on hydrogen, offshore wind, sustainable energy systems, green supply chains and joint efforts on skills development. The UK government said it will also feature collaboration on the protection of UK and Norwegian offshore infrastructure and reducing barriers to cross-border CO2 storage. An independent report found that closer cooperation between the UK and Norway could create up to 51,000 jobs and add up to £36 billion to the UK economy. © Leon Neal/PA WirePrime Minister Sir Keir Starmer and Norwegian Prime Minister Jonas Gahr Store tour the Northern Lights CCUS Plant CO2 transport and storage facility in Bergen, during a trip to Norway. Image: Leon Neal/PA Wire The Norwegian government said the UK is the country’s second-largest trading partner after the EU, with total trade in 2024 coming to approximately £38bn. More than 200 Norwegian firms operate in the UK, including Equinor, Statkraft Vårgrønn, which altogether employ over 15,000 people. In a statement, Miliband said that together, Norway and the UK can “take advantage of the opportunities ahead in the North Sea”. “Energy security is national security – and only by working with key partners like Norway can we accelerate clean power that we control, getting us off the rollercoaster of fossil fuels in these unstable times,” Miliband said. Meanwhile, Aasland said the two countries “have a unique relationship in the

The U.S. Energy Information Administration (EIA) cut its average Brent oil spot price forecast for 2025 and 2026 in its latest short term energy outlook (STEO), which was released on May 6. According to that STEO, the EIA sees the Brent spot price averaging $65.85 per barrel this year and $59.24 per barrel next year. In its previous STEO, which was released in April, the EIA projected that the Brent spot price would average $67.87 per barrel in 2025 and $61.48 per barrel in 2026. The EIA’s latest STEO sees the commodity averaging $65.04 per barrel in the second quarter of this year, $62 per barrel in the third quarter, $61 per barrel in the fourth quarter, $60 per barrel across the first and second quarters of next year, $59 per barrel in the third quarter of 2026, and $58 per barrel in the fourth quarter. In its April STEO, the EIA forecast that the Brent spot price would come in at $66.33 per barrel in the second quarter of 2025, $65.67 per barrel in the third quarter, $64 per barrel in the fourth quarter, $63 per barrel in the first quarter of next year, $62 per barrel in the second quarter, $61 per barrel in the third quarter, and $60 per barrel in the fourth quarter of 2026. “The Brent crude oil spot price averaged $68 per barrel in April, $5 per barrel lower than in March,” the EIA highlighted in its latest STEO. “Crude oil prices fell for the third consecutive month, driven primarily by expectations of lower global oil demand growth following the implementation of new tariffs from the United States and its largest trading partners,” it added. “In April, OPEC+ members also reaffirmed and accelerated their planned production increases, adding to expectations that global oil inventories

Dive Brief: Federal Energy Regulatory Commission Orders 1920 and 1920-A create space for a more holistic transmission planning framework marked by collaboration between transmission providers and state utility regulators, according to an American Council on Renewable Energy report published in April. Alternative transmission technologies, or ATTs, mentioned in the orders — dynamic line ratings, advanced power flow control, transmission switching and high-performance conductors — can speed development of a more reliable, resilient, efficient and ultimately cost-effective transmission network, principals with The Brattle Group and Grid Strategies said in “Incorporating GETs and HPCs Into Transmission Planning Under FERC Order 1920.” Transmission planners and state entities must overcome four key barriers to ATT implementation at scale: insufficient recognition of their value, misaligned incentives, overly static and deterministic planning practices, and an apparent lack of capacity to perform advanced system analyses, the report said. Dive Insight: Former FERC Commissioner Allison Clements hailed Order 1920 as “a strong step that can considerably enhance grid reliability while making electricity more affordable for consumers” shortly after its issuance last May. But Order 1920 was just an incremental step, one “forged through compromise,” Clements said.  In November, after a diverse collection of clean energy groups and mostly Republican-controlled states challenged the order in federal courts, FERC issued a modified order that it said “further enhances the role of Relevant State Entities in Long-Term Regional Transmission Planning, especially their role in shaping scenario development and cost allocation.” Among other enhancements, Order 1920-A requires transmission providers to incorporate state entities’ input on planners’ future scenario development in recognition that those scenarios will reflect states’ own plans to meet legislative or regulatory obligations, FERC said. While Order 1920 leaves the details of scenario development to transmission providers, it requires them to develop at least three “plausible and diverse” scenarios identifying

Dive Brief: The Southeast Regional Transmission Planning organization hasn’t approved a new regional transmission project in more than a decade — and is now the only region in the U.S. where that is true, according to a report written by The Brattle Group for the Carolinas Clean Energy Business Association and other renewable energy groups. Unlike neighboring utilities including Duke Energy and the Tennessee Valley Authority, Southern Co. avoided outages during 2022’s Winter Storm Elliot because it was able to import power from other nearby generators, a separate report by Telos Energy for the Southern Renewable Energy Association said. Southeastern utilities could save more than $8 billion in the long-run if they invested $5 billion in expanding the region’s grid, according to The Brattle Group. Dive Insight: Despite attracting sizeable investment under the Inflation Reduction Act, the southeastern grid is falling behind other regions of the U.S. in terms of transmission planning and expansion, according to recent reports. The SERTP process, created in 2007 in response to Federal Energy Regulatory Commission orders, has proven insufficient for the region’s needs, according to The Brattle Group. “The current SERTP regional planning process will not yield the most valuable and cost-effective transmission infrastructure needed to meet the future needs of the system,” the report said. The organization is supposed to coordinate regional transmission planning and cost allocation between 10 utilities across 12 states, but it has no independent staff and hasn’t produced or approved a new regional transmission project in over a decade, according to Brattle. Meanwhile, Telos Energy found that Southern Co. avoided outages during Winter Storm Elliot because it imported power from neighboring states at a cost of more than $52 million. Southern Co. could have defrayed some of those costs, according to the report, if it had access to lower-cost markets via